1. Field of the Invention
This invention relates to the transmission of data within a wellbore, and is especially useful in obtaining downhole data or measurements while drilling.
2. Description of the Prior Art
In rotary drilling, the rock bit is threaded onto the lower end of a drill string or pipe. The pipe is lowered and rotated, causing the bit to disintegrate geological formations. The bit cuts a bore hole that is larger than the drill pipe, so an annulus is created. Section after section of drill pipe is added to the drill string as new depths are reached.
During drilling, a fluid, often called "mud", is pumped downward through the drill pipe, through the drill bit, and up to the surface through the annulus carrying cuttings from the borehole bottom to the surface.
It is advantageous to detect borehole conditions while drilling. However, much of the desired data must be detected near the bottom of the borehole and is not easily retrieved. An ideal method of data retrieval would not slow down or otherwise hinder ordinary drilling operations, or require excessive personnel or the special involvement of the drilling crew. In addition, data retrieved instantaneously, in "real time", is of greater utility than data retrieved after time delay.
A system for taking measurements while drilling is useful in directional drilling. Directional drilling is the process of using the drill bit to drill a bore hole in a specific direction to achieve some drilling objective. Measurements concerning the drift angle, the azimuth, and tool face orientation all aid in directional drilling. A measurement while drilling system would replace single shot surveys and wireline steering tools, saving time and cutting drilling costs.
Measurement while drilling systems also yield valuable information about the condition of the drill bit, helping determine when to replace a worn bit, thus avoiding the pulling of "green" bits. Torque on bit measurements are useful in this regard. See T. Bates and C. Martin: "Multisensor Measurements-While-Drilling Tool Improves Drilling Economics", Oil & Gas Journal, Mar. 19, 1984, p. 119-137; and D. Grosso et al.: "Report on MWD Experimental Downhole Sensors", Journal of Petroleum Technology, May 1983, p. 899-907.
Formation evaluation is yet another object of a measurement while drilling system. Gamma ray logs, formation resistivity logs, and formation pressure measurements are helpful in determining the necessity of liners, reducing the risk of blowouts, allowing the safe use of lower mud weights for more rapid drilling, reducing the risks of lost circulation, and reducing the risks of differential sticking. See Bates and Martin article, supra.
Existing measurement while drilling systems are said to improve drilling efficiency, saving in excess of ten percent of the rig time; improve directional control, saving in excess of ten percent of the rig time; allow logging while drilling, saving in excess of five percent of the rig time; and enhance safety, producing indirect benefits. See A. Kamp: "Downhole Telemetry From The User's Point of View", Journal of Petroleum Technology, October 1983, p. 179-296.
The transmission of subsurface data from subsurface sensors to surface monitoring equipment, while drilling operations continue, has been the object of much inventive effort over the past forty years. One of the earliest descriptions of such a system is found in the July 15, 1935 issue of The Oil Weekly in an article entitled "Electric Logging Experiments Develop Attachments for Use on Rotary Rigs" by J. C. Karcher. In this article, Karcher described a system for transmitting geologic formation resistance data to the surface, while drilling.
A variety of data transmission systems have been proposed or attempted, but the industry leaders in oil and gas technology continue searching for new and improved systems for data transmission. Such attempts and proposals include the transmission of signals through cables in the drill string, or through cables suspended in the bore hole of the drill string; the transmission of signals by electromagnetic waves through the earth; the transmission of signals by acoustic or seismic waves through the drill pipe, the earth, or the mudstream; the transmission of signals by relay stations in the drill pipe, especially using transformer couplings at the pipe connections; the transmission of signals by way of releasing chemical or radioactive tracers in the mudstream; the storing of signals in a downhole recorder, with periodic or continuous retrieval; and the transmission of data signals over pressure pulses in the mudstream. See generally Arps, J. J. and Arps, J. L.: "The Subsurface Telemetry Problem-A Practical Solution", Journal of Petroleum Technology, May 1964, p. 487-93.
Many of these proposed approaches face a multitude of practical problems that foreclose any commercial development. In an article published in August of 1983, "Review of Downhole Measurement-While-Drilling Systems", Society of Petroleum Engineers Paper Number 10036, Wilton Gravley reviewed the current state of measurement while drilling technology. In his view, only two approaches are presently commercially viable: telemetry through the drilling fluid by the generation of pressure-wave signals and telemetry through electrical conductors, or "hardwires".
Pressure-wave data signals can be sent through the drilling fluid in two ways: a continuous wave method, or a pulse system.
In a continuous wave telemetry, a continuous pressure wave of fixed frequency is generated by rotating a valve in the mud stream. Data from downhole sensors is encoded on the pressure wave in digital form at the slow rate of 1.5 to 3 binary bits per second. The mud pulse signal loses half its amplitude for every 1,500 to 3,000 feet of depth, depending upon a variety of factors. At the surface, these pulses are detected and decoded. See generally the W. Gravley article, supra, p. 1440.
Data transmission using pulse telemetry operates several times slower than the continuous wave system. In this approach, pressure pulses are generated in the drilling fluid by either restricting the flow with a plunger or by passing small amounts of fluid from the inside of the drill string, through an orifice in the drill string, to the annulus. Pulse telemetry requires about a minute to transmit one information word. See generally the W. Gravley article, supra, p. 1440-1441.
Despite the problems associated with drilling fluid telemetry, it has enjoyed some commercial success and promises to improve drilling economics. It has been used to transmit formation data, such as porosity, formation radioactivity, formation pressure, as well as drilling data such as weight on bit, mud temperature, and torque on bit.
Teleco Oilfield Services, Inc., developed the first commercially available mudpulse telemetry system, primarily to provide directional information, but now offers gamma logging as well. See Gravley article, supra; and "New MWD-Gamma System Finds Many Field Applications", by P. Seaton, A. Roberts, and L. Schoonover, Oil & Gas Journal, Feb. 21, 1983 p. 80-84.
A mudpulse transmission system designed by Mobil R. & D. Corporation is described in "Development and Successful Testing of a Continuous-Wave, Logging-While-Drilling Telemetry System", Journal of Petroleum Technology, October 1977, by Patton, B. J. et al. This transmission system has been integrated into a complete measurement while drilling system by The Analyst/Schlumberger.
Exploration Logging, Inc., has a mudpulse measurement while drilling service in commercial use that aids in directional drilling, improves drilling efficiency, and enhances safety. Honeybourne, W.: "Future Measurement-While-Drilling Technology Will Focus On Two Levels", Oil & Gas Journal, Mar. 4, 1985, p. 71-75. In addition, the Exlog system can be used to measure gamma ray emissions and formation resistivity while drilling occurs. Honeybourne, W.: "Formation MWD Benefits Evaluation and Efficiency", Oil & Gas Journal, Feb. 25, 1985, p. 83-92.
The chief problems with drilling fluid telemetry include: (1) a slow data transmission rate; (2) high signal attenuation; (3) difficulty in detecting signals over mud pump noise; (4) the inconvenience of interfacing and harmonizing the data telemetry system with the choice of mud pump, and drill bit; (5) telemetry system interference with rig hydraulics; and (6) maintenance requirements. See generally, Hearn, E.: "How Operators Can Improve Performance of Measurement-While-Drilling Systems", Oil & Gas Journal Oct. 29, 1984 , p. 80-84.
The use of electrical conductors in the transmission of subsurface data also presents an array of unique problems. Foremost, is the difficulty of making a reliable electrical connection at each pipe junction.
Exxon Production Research Company developed a hardwire system that avoids the problems associated with making physical electrical connections at threaded pipe junctions. The Exxon telemetry system employs a continuous electrical cable that is suspended in the pipe bore hole.
Such an approach presents still different problems. The chief difficulty with having a continuous conductor within a string of pipe is that the entire conductor must be raised as each new joint of pipe is either added or removed from the drill string, or the conductor itself must be segmented like the joints of pipe in the string.
The Exxon approach is to use a longer, less frequently segmented conductor stored down hole in a spool which will yield more cable, or take up more slack, as the situation requires.
However, the Exxon solution requires that the drilling crew perform several operations to ensure that this system functions properly, and it requires some additional time in making trips. This system is adequately described in L. H. Robinson et al.: "Exxon Completes Wireline Drilling Data Telemetry System", Oil & Gas Journal, Apr. 14, 1980, p. 137-148.
Shell Development Company has pursued a telemetry system that employs modified drill pipe, having electrical contact rings in the mating faces of each tool joint. A wire runs through the pipe bore, electrically connecting both ends of each pipe. When the pipe string is "made up" of individual joints of pipe at the surface, the contact rings are automatically mated.
While this system will transmit data at rates three orders of magnitude greater than the mud pulse systems, it is not without its own peculiar problems. If standard metallic-based tool joint compound, or "pipe dope", is used, the circuit will be shorted to ground. A special electrically non-conductive tool joint compound is required to prevent this. Also, since the transmission of the signal across each pipe junction depends upon good physical contact between the contact rings, each mating surface must be cleaned with a high pressure water stream before the special "dope" is applied and the joint is made-up.
The Shell system is well described in Denison, E. B.: "Downhole Measurements Through Modified Drill Pipe", Journal Of Pressure Vessel Technology, May 1977, p. 374-379; Denison, E. B.: "Shell's High-Data-Rate Drilling Telemetry System Passes First Test", The Oil & Gas Journal, June 13, 1977, p. 63-66; and Denison, E. B.: "High Data Rate Drilling Telemetry System", Journal of Petroleum Technology, February 1979, p. 155-163.
A search of the prior patent art reveals a history of attempts at substituting a transformer or capacitor coupling in each pipe connection in lieu of the hardwire connection. U.S. Pat. No. 2,379,800, Signal Transmission System, by D. G. C. Hare, discloses the use of a transformer coupling at each pipe junction, and was issued in 1945. The principal difficulty with the use of transformers is their high power requirements. U.S. Pat. No. 3,090,031, Signal Transmission System, by A. H. Lord, is addressed to these high power losses, and teaches the placement of an amplifier and a battery in each joint of pipe.
The high power losses at the transformer junction remained a problem, as the life of the battery became a critical consideration. In U.S. Pat. No. 4,215,426, Telemetry and Power Transmission For Enclosed Fluid Systems, by F. Klatt, an acoustic energy conversion unit is employed to convert acoustic energy into electrical power for powering the transformer junction. This approach, however, is not a direct solution to the high power losses at the pipe junction, but rather is an avoidance of the larger problem.
Transformers operate upon Faraday's law of induction. Briefly, Faraday's law states that a time varying magnetic field produces an electromotive force which may establish a current in a suitable closed circuit. Mathematically, Faraday's law is: emf=d.PHI./dt Volts; where emf is the electromotive force in volts, and d.PHI./dt is the time rate of change of the magnetic flux. The negative sign is an indication that the emf is in such a direction as to produce a current whose flux, if added to the original flux, would reduce the magnitude of the emf. This principal is known as Lenz's Law.
An iron core transformer has two sets of windings wrapped about an iron core. The windings are electrically isolated, but magnetically coupled. Current flowing through one set of windings produces a magnetic flux that flows through the iron core and induces an emf in the second windings resulting in the flow of current in the second windings.
The iron core itself can be analyzed as a magnetic circuit, in a manner similar to DC electrical circuit analysis. Some important differences exist however, including the often nonlinear nature of ferromagnetic materials.
Briefly, magnetic materials have a reluctance to the flow of magnetic flux which is analogous to the resistance materials have to the flow of electric currents. Reluctance is a function of the length of a material, L, its cross section, S, and its permeability U. Mathematically, Reluctance=L .div.(U.times.S), ignoring the nonlinear nature of ferromagnetic materials.
Any air gaps that exist in the transformer's iron core present a great impediment to the flow of magnetic flux. This is so because iron has a permeability that exceeds that of air by a factor of roughly four thousand. Consequently, a great deal of energy is expended in relatively small air gaps in a transformer's iron core. See generally, HAYT: Engineering Electro-Magnetics, McGraw Hill, 1974 Third Edition, p. 305-312.
The transformer couplings revealed in the above-mentioned patents operate as iron core transformers with two air gaps. The air gaps exist because the pipe sections must be severable.
Attempts continue to further refine the transformer coupling, so that it might become practical. In U.S. Pat. No. 4,605,268, Transformer Cable Connector, by R. Meador, the idea of using a transformer coupling is further refined. Here the inventor proposes the use of closely aligned small toroidal coils to transmit data across a pipe junction.
To date none of the past efforts have yet achieved a commercially successful hardwire data transmission system for use in a wellbore.
For data transmission systems to operate to full advantage, it is desirable that wellbore tools, such as drill bits and sensor subassemblies, be produced to cooperate therewith. Wellbore tools could provide significant amounts of useful data. For example, information pertaining to wellbore conditions such as temperature, pressure, and orientation, to formation conditions such as porosity, resistivity, and gamma ray emission, and to tool conditions such as temperature, pressure, torque, wear and probable failure is highly relevant to drilling operations, and not without significant practical and monetary value.
Wellbore tools are often subject to failure while within the wellbore; such failures cause expensive drilling delays. In addition, wellbore tool failures may make further drilling difficult or impossible to accomplish, and often require the specialized skills of oil field service companies to recover or "fish" broken tools from the wellbore.
For example, drill bits are frequently subject to catastrophic mechanical failure while in the wellbore due to loss of lubricant, detached drilling cones, bearing failure, and washout. While such mechanical failures are quite common, they are difficult to predict in the individual case. A variety of drill bit conditions exist which, if known by the drilling crew at the surface, could serve to warn of imminent drill bit failure. Such conditions include lubricant pressure, bit temperature, and the presence of moisture in sealed drill bit cavities.
However, information pertaining to wellbore tool conditions is largely untapped by present drilling technology, due in large part to the difficulty encountered in the transmission of data across the threaded junctions which separate the wellbore tools from drill strings. Of course, the main difficulty encountered in known contactless transmission systems is the significant power requirements.